ALBERT

Description: Integrated airborne and ground geophysical studies were conducted in parts of Ilesha schist belt, southwestern Nigeria. The goal was to provide a useful guide for mineral prospecting, with the hope of considerably narrowing down the future search for mineral deposits within the study area. Aeromagnetic and aeroradiometric data were analyzed for the reconnaissance study. In addition, the reduction-to-equator transform, analytic signal, tilt derivative, and Euler deconvolution filters were applied to the aeromagnetic data to enhance shallow and deep geologic features. The aeroradiometric data were used to determine spatial variations in the concentrations of uranium (U), thorium (Th), and potassium (K) in near-surface rocks and to map spatial lithologic changes. The 2D-magnetic sections, radiometric profiles, inverted resistivity, and induced polarization (IP) sections were generated from the integrated geophysical data. The electrical resistivity tomography (ERT) results reveal the subsurface heterogeneity (to a depth of approximately 197 m) and varied geoelectric layers (topsoil, lateritic-clay, weathered rock, and basement rock). The IP sections show varying degrees of chargeability and features that suggest the presence of disseminated mineralized bodies concealed in some areas. The overburden thickness varies between 4 and 85 m as determined from the 2D-magnetic and electric resistivity sections. Anomalous peaks on profiles of elemental ratios (eTh/K, eTh/eU, and K/eU) correlate with the results of IP and ERT. Data sets are well correlated and highlight areas with relevant structural and lithologic signatures favorable for mineral deposition. The methodology adopted in our research is well adapted, and the interpretation techniques provided insight into regional and local lithostructural settings. These anomalous areas are suggested as targets for future exploration works.

Description: Hydraulic fracturing (HF) and horizontal drilling are essential to the development of shale gas and oil. Production depends on the stimulation success. During fracture initiation, propagation, and closure, cracks emit acoustic waves; these can be monitored in real time as microseismics in the field and as acoustic emissions (AEs) in the laboratory. AEs are the laboratory equivalent of field-scale microseismics and contain detailed information about HF fracture mechanics. The number of acoustic events correlates with the number of induced fractures and hence the stimulation volume. Three HF protocols under dry conditions were carried out on Tennessee sandstone: (1) a constant injection rate, (2) a precyclic injection, and (3) a variable-rate injection test. All three tests were performed under the same principal stress conditions: vertical stress of 10.3 MPa (1500 psi), minimum horizontal stress of 3.5 MPa (500 psi), and maximum horizontal stress of 20.7 MPa (3000 psi). In total, 16 piezoelectric transducers were mounted around a cylindrical sample to record the AEs. We have performed postsignal processing to extract AE event attributes, including the amplitudes, signal-to-noise ratio, arrival time, event location (with the velocity-anisotropy input), and frequency analyses. The AE events associated with the constant-rate injection test possessed the lowest frequencies (150–270 kHz). The variable-rate test AE events possessed higher frequencies (160–310 kHz), whereas the precyclic injection had events with the highest frequencies, peaking at 330 kHz. Acoustic events before failure had lower amplitudes, but higher frequency compared to those recorded postbreakdown, suggesting different failure modes. Precyclic injection induced the greatest number of locatable events before and after failure.

Description: We have evaluated the results of a receiver decimation study in a deepwater context using separated wavefield imaging (SWIM) algorithms to provide extended illumination for imaging without ocean-bottom node (OBN) positioning constraints. We carried out subsurface imaging using the SWIM imaging technique with a reduced OBN layout, and we compared the results with those from conventional one-way wave-equation migration. We found from the results that the SWIM algorithm makes it possible to reduce the OBN layout while obtaining a similar subsurface image with the same shot geometry, which allows a reduced receiver acquisition effort, offers more geometry flexibility without affecting the image quality, with a potentially significant reduction of acquisition cost and 4D processing turnaround time.

Description: Tight-gas sandstone reservoirs of the Ordos Basin in China are characterized by high rock-fragment content, dissimilar pore types, and a random distribution of fluids, leading to strong local heterogeneity. We model the seismic properties of these sandstones with the double-double porosity theory, which considers water saturation, porosity, and the frame characteristics. A generalized seismic wavelet is used to fit the real wavelet, and the peak frequency-shift method is combined with the generalized S-transform to estimate attenuation. Then, we establish rock-physics templates (RPTs) based on P-wave attenuation and impedance. We use the log data and related seismic traces to calibrate the RPTs and generate a 3D volume of rock-physics attributes for the quantitative prediction of saturation and porosity. The predicted values are in good agreement with the actual gas production reports, indicating that the method can be effectively applied to heterogeneous tight-gas sandstone reservoirs.

Description: The second member of the Kongdian Formation (usually abbreviated as the E k2 shale) is one of the most significant exploring targets for shale oil at the Cangdong Sag of the central Bohai Bay Basin. It consists of siliceous shale, mixed shale, and calcareous shale. To better understand why organic matter accumulated in the E k2 shale, we have analyzed major and trace elemental compositions to reconstruct the provenance and sedimentary environment. Tectonic discriminatory diagrams suggest that the tectonic setting of the parental rocks for the E k2 shale belonged to the Continental Island Arc. The distribution patterns of trace elements and rare earth elements + yttrium (REEs + Y) are close to the intermediate igneous rock. The ratios of Al2O3/TiO2 ranging from 21.41 to 27.59 with a mean value of 23.93 also demonstrate a parental rock of the intermediate igneous rock. Siliceous and mixed shales indicate K2O/Al2O3 of 0.17–0.29, chemical index of weathering of 28.79–97.79, plagioclase index of alteration of 38.24–95.57, and chemical index of alteration of 40.29–80.23. These weathering proxies denote that the E k2 shale underwent a low weathering degree in an arid climate and a high weathering degree in a semiarid climate. The V/(V + Ni) ratios and pyrite framboids indicate an anoxic sedimentary condition. The δ18O values of carbonate minerals in the E k2 shale range from −9.8‰ to 0.7‰, and they are positively correlated to the δ13C values. The Sr/Ba ratios, δ18O, and chemical mineral associations indicate that siliceous and mixed shales were deposited in a fresh to brackish anoxic water column under a semiarid climate. Whereas calcareous shale was deposited in a saline to hypersaline anoxic water column under an arid climate.

Description: The complete characterization of a reservoir requires accurate determination of properties such as the porosity, gamma ray, and density, among others. A common workflow is to predict the spatial distribution of properties measured by well logs to those that can be computed from the seismic data. In general, a high degree of scatter of data points is seen on crossplots between P-impedance and porosity, or P-impedance and gamma ray, suggesting great uncertainty in the determined relationship. Although for many rocks there is a well-established petrophysical model correlating the P-impedance to porosity, there is not a comparable model correlating the P-impedance to gamma ray. To address this issue, interpreters can use crossplots to graphically correlate two seismically derived variables to well measurements plotted in color. When there are more than two seismically derived variables, the interpreter can use multilinear regression or artificial neural network analysis that uses a percentage of the upscaled well data for training to establish an empirical relation with the input seismic data and then uses the remaining well data to validate the relationship. Once validated at the wells, this relationship can then be used to predict the desired reservoir property volumetrically. We have described the application of deep neural network (DNN) analysis for the determination of porosity and gamma ray over the Volve field in the southern Norwegian North Sea. After using several quality-control steps in the DNN workflow and observing encouraging results, we validate the final prediction of the porosity and gamma-ray properties using blind well correlation. The application of this workflow promises significant improvement to the reservoir property determination for fields that have good well control and exhibit lateral variations in the sought properties.

Description: Recent advancements in distributed acoustic sensing (DAS) technology open new ways for borehole-based seismic monitoring of CO2 geosequestration. Compared to 4D surface seismic monitoring, repeated vertical seismic profiling (VSP) surveys with DAS receivers considerably reduce the cost and invasiveness of time-lapse CO2 monitoring. However, standard borehole imaging techniques cannot provide the same level of reservoir illumination as 3D surface seismic. The performance of VSP imaging can be significantly improved with interferometric utilization of free-surface multiples. We have developed a feasibility study of interferometric imaging with a synthetic walkaway VSP data set, followed by its application to field walkaway VSP data recorded by conventional borehole geophones and two types of DAS (standard and engineered fibers). Both experiments (synthetic and field) demonstrate that interferometric imaging is a viable method to extend the subsurface image beyond the coverage of standard VSP imaging. Specifically, the interferometry approach provides a more detailed upper section of the subsurface, whereas standard migration of primary reflections provides a more detailed bottom part of the image. Comparison of the standard and engineered fibers indicates that both fibers are sensitive to free-surface multiples, but the engineered fiber provides a much higher signal-to-noise ratio; thus, it is preferable for interferometric imaging with multiples. The result obtained with the engineered DAS cable indicates that in the depth range suitable for both methods, the VSP interferometric image of the reflectors is comparable to the surface seismic image. The experiment on the field DAS data proves that DAS is sensitive enough to record the nonprimary wavefield for imaging and monitoring of the subsurface.

Description: Distributed acoustic sensing (DAS) technologies are now becoming widespread, particularly in vertical seismic profiling (VSP). Being a spatially densely sampled recording of the seismic wavefield, DAS data provide an extended measurement compared with point geophone VSP. We have developed a basic theory that enables an intuitive geophysical understanding of DAS data amplitudes using the concepts of kinetic and potential energy and their fluxes. We start by relating DAS and geophone measurements to potential energy and kinetic energy, respectively. We use this relationship and energy balancing along the well to construct a scheme for inverting DAS and geophone wavefields for density and velocity simultaneously. Then, recognizing that it may be impractical to have geophones and DAS, we adopt a second inversion scheme that eliminates the need for geophones and uses up- and downgoing DAS wavefields instead. There is no need for first-break picking or windowing the data, and the full-length DAS records can be used in both inversion schemes. We test these inversion schemes on 2D elastic synthetics.

Description: Energy exploration is becoming increasingly complex worldwide, and tight sandstone gas is an important field for the future development of the oil and gas industry. For the reservoir properties of the Shaximiao Gas Reservoir on the eastern slope of the Western Sichuan Depression in the Sichuan Basin, western China, it was found that the low-resistance characteristics of the reservoir complicate the gray characteristics among reservoir fluid property parameters. Some commonly used fluid property identification techniques, such as the flow zone index method, correlation analysis method of logging parameters, and traditional mathematical statistical methods, have poor fluid property evaluation results. Therefore, how to eliminate the influence of the gray features among the reservoir parameters on the identification of reservoir fluid properties and how to accurately identify the reservoir fluid properties are urgent problems that need to be solved. In this paper, we have developed a new method for identifying the fluid properties of tight sandstone reservoirs by combining gray system theory and multivariate statistical theory. This method can perform gray correlation weight analysis on parameters (combined parameters) closely related to fluid properties; furthermore, the logging identification method based on gray correlation weight analysis is used to identify reservoir fluid properties. The results indicate that the gray correlation weight analysis can accurately characterize the gray characteristics of reservoir fluid parameters and that the gray comprehensive correlation weight results are in good agreement with the production status of the studied gas reservoir. We used the method to identify the fluid properties of the target layer in 58 wells in the study area, and the discrimination rate of the model was 86.5%. In addition, the new model was used to predict the reservoir fluid properties of 12 newly drilled wells in the study area and the accuracy of the reservoir fluid property prediction was 91.67%.

Description: We analyzed a synthetic transfer zone and its associated fault planes and relay ramp in Penobscot, a potential offshore field in the Scotian Basin. Transfer zones are structural areas where one fault dies out and another fault begins, forming a relay ramp in the middle. They can be categorized as divergent, convergent, and synthetic transfer zones depending on the relative location and dipping directions of the faults. These zones not only play an important role in fluid migration but also help interpreters delineate secondary features such as fractures, splay shears, and Riedel faults. Commonly, those faults would branch into smaller splays and the relay ramp can get “breached” with connecting faults with the increase of slip. The study area in the Scotian Basin is characterized by two major listric normal faults dipping in the same direction giving rise to a synthetic transfer zone. These faults are clearly visible on seismic attributes, including curvature and coherence slices extracted along the top of the Cretaceous Petrel Formation. However, when analyzing the seismic attributes along the overlying Wyandot Formation’s top, we observe channel-like features, which run parallel as well as at an angle to these faults. However, when we performed further analysis using seismic amplitude’s vertical slices, interpreted horizons, and seismic attributes, we found that these features are not channels. We divided the features into two types: The first type is parallel to the main faults and can be associated with the grabens formed by synthetic and antithetic secondary faults (northeast–southwest); the second type is related to the polygonal faulting associated with differential compaction and gravitational loading of the Wyandot Chalk Formation. Apart from the two lineations, there are north-northeast–south-southwest-oriented lineations, which are an impression of basement faulting, and north-northwest–south-southeast-oriented lineations representing the acquisition footprint. Geological feature: Synthetic and antithetic faults in a synthetic transfer zone Seismic appearance: Channel-like feature on seismic attribute horizon slices Alternative interpretations: Channels Features with similar appearance: Steep slope channels Formation: Wyandot Age: Late Cretaceous Location: Penobscot, Nova Scotia, Canada Seismic data: Open-source SEG Analysis tools: Coherence and curvature attributes